The embodiments described herein relate generally to soundings within the earth based upon electrical fields. As used herein, “earth” or “Earth” generally refers to any region in which a borehole may be located including, for example, the lithosphere. Electromagnetic (EM) geophysical surveys probe electrical resistivity, or equivalently, conductivity, in the earth as a function of depth. Typical targets of interest include ore bodies, hydrocarbons, water, steam, proppants, hydraulic fracture (or fracking) fluids, salts and other substances injected into the ground, and geological or formation features surrounding such targets as well as environmental pollutants. Geophysical exploration is also used for regional characterization to determine if a particular area displays particular characteristics (e.g. diamond exploration relies on focusing on regions which display particular characteristics of the lithosphere-asthenosphere boundary along with other markers). Since the resistivities of such targets and the surrounding medium or surrounding geology may be quite dissimilar, the targets may be discriminated by measuring their subsurface resistivities when subjected to an electromagnetic field. Using this methodology, the depth, thickness, lateral extent and characterization of materials, or the characterization of an entire 3D volume of interest may be determined or monitored.
The source of the EM field used in a geophysical survey may naturally occur or be manmade. Whether naturally occurring or manmade, the source may produce a primary magnetic and/or electric field that varies in time, and this primary field produces a secondary field in a conductive medium such as the earth. For example, an applied primary electric field produces electric currents in the earth that have an associated time varying magnetic field, and a time varying magnetic field induces electric currents that result in a secondary electric field. The electrical properties of the earth and rate of change of the field determine the relative magnitudes of the secondary field to the primary field. The combination of primary and secondary fields results in combined electromagnetic interaction with the earth even for a source arranged to produce solely a time varying electrical or magnetic field.
The distribution of electric current flow produced by an EM source is in large part determined by the three-dimensional (3D) resistivity distribution within the earth. Given a well-chosen set of electric field measurements at the surface or at depth within a borehole, together with a sufficient placement of source electrodes, the 3D resistivity variation over the region where current is flowing may be inferred. The current is typically measured by a suitably calibrated array of electric and/or magnetic field sensors. The resulting 3D resistivity variation can be used to project the distribution of ores, hydrocarbons, water or other targets within the measured volume.
The understanding of the relationship of subsurface geology and wellbore placement is limited to either surface systems, which provide overall low distance resolution and/or formation property accuracy, or downhole systems, which only have the ability to investigate the area immediately around the wellbore. This affects well placement, reservoir production and drilling safety because there is not a full understanding of the subsurface geology between the wellbores and ahead of the bit during the drilling process. Employing methods to create and enhance 1D, 2D, 2.5D and particularly 3D resistivity mapping of subsurface formations provides a more complete understanding of the environment, improves reservoir recovery and decreases the impact of unexpected hazards and changes ahead of the bit.
Many factors come into play in the effective placement of wellbores in positions to produce a maximum volume of hydrocarbons while avoiding drilling and completion problems. Two significant factors are the understanding of what fluids are in the formations and the correlation of the wellbore to the depth of the formations. Better wellbore placement (e.g., through geosteering) can improve drilling efficiency, increase hydrocarbon production, extend reservoir life and avoid drilling hazards such as pore pressure and encountering of unexpected geological features that result in drilling fluid loss or other problems. Current methods to place the wellbore within a subsurface geology are surface and subsurface seismic, EM and seismic tomography, and wellbore formation evaluation logging. Each of these has limitations in resolving information about the fluid in the formations and in distance resolution, and/or they are operationally intrusive (i.e., they require significant changes in work methods, which is costly).
Resistivity is the primary method used to determine whether hydrocarbons or saltwater are present in formations. Seismic information requires knowledge of the low frequency sound velocity in each formation to determine distance, access to cost-prohibitive equipment and does not provide resistivity values used to determine formation fluid type. Tomography requires access to producing wellbores, which are typically not located in optimal locations to allow evaluation, and production has to be halted during the tomography process. Use of drilling formation evaluation tools provides high accuracy resistivity values with distance from wellbore placement but has a very limited depth of investigation (that is, how much subsurface geology can be mapped) and are limited or cannot investigate regions in front of the drill. To summarize, seismic data typically has low distance resolution and no resistivity information about what fluids are in the formations. EM and seismic tomography methods (as well as cross-well EM methods) require access to existing wellbores and that production be halted, therefore making them unlikely to be used during the drilling process. Logging-while-drilling (LWD) formation evaluation tools have acceptable resistivity and distance accuracy, but the depth of investigation is limited to 20 to 100 feet from the wellbore and generally if not always only lateral to the wellbore.
FIGS. 1-3 are for reference and meant to introduce a small fraction of the configurations possible. For example, they show a plurality of deviated and horizontal wells, but configurations can be as simple as a single vertical well. FIG. 1 represents a shale well arrangement (unconventional) where many wells 100 are drilled from confined surface locations to many reservoir laterals. Secondary surface locations (coming in from the right relative to FIG. 1) can be seen interacting with the primary pad. The area shown is approximately 9 square miles. FIG. 2 is an isometric view of four horizontal wells 200-203. The patterned block around well 202 is somewhat representative of current resistivity mapping capabilities, with different patterns representing different resistivity values, although the depth of investigation is not to scale. FIG. 3 represents a traditional offshore platform configuration where wells are deviated to reservoirs (i.e., not horizontal). In particular, a plurality of wells is shown coming from two platforms (not visible), with a first set of wells 300 corresponding to the first platform and a second set of wells 305 corresponding to the second platform. FIG. 4 is also for reference and meant to show the prior art related to downhole logging-while-drilling resistivity tools. Specifically, FIG. 4 shows a logging device 30 from U.S. Pat. No. 4,553,097, which is incorporated herein by reference.
More generally, the prior art as a whole shows that the resistivity of any subsurface geology can be imaged using various surface methods. The issue is that these surveys are limited in their depth extent, have accuracy and resolution limitations, and can be negatively influenced by galvanic surface sensor setup and performance, including but not limited to electrochemical behavior and noise caused by poor coupling to the earth. Other techniques have been developed that partially address these limitations but also introduce other issues. These techniques include the use of EM tomography and logging-while-drilling tools. However, EM tomography requires wellbore intervention, has a fixed subsurface volume it can image, and has no real-time applicability. Logging-while-drilling tools cannot see in front of the drilling bit and only a very limited subsurface volume around the wellbore being drilled can be imaged.
Traditional EM surveys, such as surface-to-surface EM, borehole-to-surface EM and cross-well EM, as well as depth-to-surface EM and the more theoretical surface-to-depth EM methods, utilize just one or a small plurality of source points. For example, for borehole-to-surface methods, the surveyor might deploy a source electrode down a vertical borehole and transmit at just four different depth locations. Transmitting at more than one depth location improves resolution, but increasing the number of transmit depths quickly diminishes in added value and dramatically increases costs. Additional background information is included in U.S. Pat. No. 9,405,032, U.S. Patent Application Publication Nos. 2015/0160364 and 2015/0219784 and International Patent Application Publication Nos. WO 2015/073393, WO 2015/127211 and WO 2015/153983, which are incorporated herein by reference.